While the invention will be described with reference to CO2 and SO2, it may be equally applicable to gas streams containing CO2 and other sulfurous acid gases such as H2S, or other acidic gases which form stronger acids than CO2 such as HF, HCl and NO2.
There is growing pressure for stationary producers of greenhouse gases to dramatically reduce their atmospheric emissions. Of particular concern is the emission of carbon dioxide (CO2) into the atmosphere. One method of reducing atmospheric CO2 emissions is through its capture at a point source and subsequent storage in geological or other reservoirs.
The process for capturing CO2 from power station and other combustion device flue gases is termed post combustion capture (PCC). In post combustion capture, the CO2 in flue gas is first separated from nitrogen and residual oxygen using a suitable solvent in an absorber. The solvent is usually an aqueous basic mixture containing components undergoing a chemical reaction with acid gases such as CO2. It might contain amines (e.g. alkanolamines, ammonia, alkylamines) and/or inorganic salts (e.g. carbonate or phosphate). The CO2 is subsequently removed from the solvent in a process called stripping (or regeneration), thus allowing the solvent to be reused. The stripped CO2 is liquefied by compression and cooling, with appropriate drying steps to prevent hydrate formation. PCC in this form is applicable to a variety of stationary CO2 sources including power stations, steel plants, cement kilns, calciners and smelters.
When CO2 is absorbed into an aqueous solution a number of reactions can occur. They are shown by the following equations where (1) is hydration of gaseous CO2, (2) is the reaction of CO2 with water to form carbonic acid, (3) is the reaction of CO2 with hydroxide to form bicarbonate and (4) and (5) are the carbonic acid-bicarbonate-carbonate acid-base equilbria.

If an amine, or multiple amines, are present in solution a number of additional reactions may occur. If the amine is a sterically free primary or secondary amine such as monoethanolamine (MEA) or diethanolamine (DEA) the following reactions can occur between CO2 and each amine. Equation (6) is the formation of a carbamate species via a nitrogen-carbon bond formation between the amine and CO2. This is generally the kinetically fastest reaction of those that occur with CO2. Equation (7) is the amine acid-base equilibrium. For polyamines the reactions of equation (6) and (7) may occur for each nitrogen. For sterically hindered and tertiary amines only the acid-base equilibrium of equation (7) occurs.

Combustion devices that utilise fuel containing sulfur (such as coal and oil) also produce sulfur dioxide (SO2) as a combustion product in their flue gas. In untreated flue gas from coal fired power stations, the largest source of CO2 emissions globally, the SO2 content varies between 100-5000 ppmv. In other off-gases such as those of smelters, the SO2-content might reach levels in excess of 10%. SO2 emissions have long been recognised as the primary cause of acid rain and the subsequent environmental degradation that results. As a consequence flue gas desulfurisation (FGD) technology was developed to capture the SO2 from combustion flue gas prior to its emission to the atmosphere. FGD is utilised primarily in the USA, Europe, Japan and increasingly in China. After FGD the sulfur content is usually reduced to levels between 10 and 100 ppm, depending on the particular FGD technology used, the original sulfur content in the coal and the legislative requirements for sulfur content in the remaining flue gases.
As SO2 and CO2 are both acid gases, with SO2 being a significantly stronger acid, the presence of SO2 in flue gas degrades the performance of CO2 capture. When SO2 is absorbed into an aqueous solution analogous reactions occur to those for CO2. Equation (8) is hydration of gaseous SO2, equation (9) is the formation of sulfurous acid, equation (10) is the formation of bisulfate and equations (11) and (12) are the sulfurous acid-bisulfite-sulfite acid-base equilibria. The oxidation of sulfite to sulfate, which may occur in the presence of molecular oxygen, has not been included as its small reaction rate means it has no impact upon the invention described herein.

However, unlike CO2, SO2 does not react directly with amines present in solution. The other significant difference is that SO2 is a much stronger acid and is absorbed much more rapidly than CO2. The pKa's of bisulfite and sulfurous acid are 7.17 and 1.85 respectively at 25° C., compared to 10.3 and 3.34 for bicarbonate and carbonic acid. Also the reaction rate constant of SO2 and water is almost two orders of magnitude larger than the largest known rate constant for CO2 reacting with an amine, which is its reaction with piperazine (PZ). Considering water is present at a much larger concentration than any amine the overall rate of reaction for SO2 will be greater still.
The physical solubility of SO2 in an aqueous solution is over an order of magnitude larger than CO2. The Henry coefficient at 25° C. (defined as the gas phase partial pressure over the liquid phase concentration of the gas,
      H    i    =            P      i              c      i      for SO2 is 82.46 KPa·L·mol−1 while for CO2 it is 3265 kPa·L·mol−1. They both share similar diffusion coefficients. The combination of greater physical solubility, faster reaction rate and greater acidity means that when both CO2 and SO2 are simultaneously present in flue gas SO2 is absorbed preferentially to and more rapidly than CO2. This is the case even if the gas phase concentration of SO2 is significantly lower than CO2.
Modelling of CO2 and SO2 absorption into a falling thin film of aqueous MEA has been completed to illustrate this selectivity. A falling thin film is the type of hydrodynamic environment found in packed columns commonly used for CO2 capture applications where a liquid film falls under gravity over packing material and is counter-currently contacted with a gas stream. Chemical diffusion and reaction in a thin film has been modelled by solving the appropriate partial differential equations and simultaneous equations needed to describe the reactions between aqueous MEA, CO2 and SO2. The method is described in detail in G. Puxty and R. Rowland, Env. Sci. Technol. 2011, 45, 2398-2405. FIG. 1 is a plot showing the impact of gas phase SO2 concentration on the CO2 absorption flux into a thin film of 30% w/w aqueous MEA at 40° C. as determined by modelling (filled markers). The gas phase CO2 concentration was 10 kPa and exposed to the film for 0.3 seconds, the liquid CO2 loading (mol CO2/mol MEA) was varied between 0-0.5 and the gas phase SO2 concentration between 0-800 ppmv. The conditions for the modelling were chosen to be similar to those used for experimental validation of the patent concept, as described in the next paragraph. In all cases as the SO2 concentration increases the CO2 absorption flux is very slightly reduced. This is due to the preferential absorption of SO2 and the associated acidification of the solution. This effect is most pronounced if the solvent is loaded with CO2, as would be the case in real operation. Also shown is the SO2 absorption flux, which is observed to increase linearly with increasing SO2 concentration in the gas phase. This indicates that the rate of chemical reaction with SO2 is so fast that its absorption flux is entirely controlled by the gas side.
FIG. 2 is a plot of measurements of the impact of gas phase SO2 on the CO2 absorption flux into 30% aqueous MEA at 40° C. These measurements were made using the wetted-wall contactor shown in FIG. 3. FIG. 3 shows a wetted-wall contactor comprising a liquid inlet (301), a liquid outlet (302), a gas inlet (303), and a thin liquid film (304). A detailed description of this apparatus is given in G. Puxty, R. Rowland and M. Attalla, Chem. Eng. Sci. 2010, 915-922 and it was used as described with the following modifications: the addition of SO2 as a feed gas; use of 2 mol·dm−3 H2SO4 in the saturator; and the addition of an SO2 gas analyser. A 1 dm3 min−1 inlet gas stream containing 10 kPa CO2, 0-800 ppmv SO2 and the remainder N2 was contacted with at 40° C. with falling thin liquid film flowing at 121.4 cm3 min−1. The concentration of CO2 and SO2 in the outlet gas stream was measured using the gas analyser and the absorption fluxes determined. The liquid CO2 loading was varied between 0-0.5. This apparatus mimics the gas-liquid contacting of packed columns typically used for gas absorption processes. As can be observed the behaviour is consistent with the results predicted from modelling for both CO2 and SO2. As the SO2 concentration increases in the gas-phase the CO2 absorption flux is slightly reduced. The selectivity for SO2 absorption is further confirmed by the fact that the SO2 content in the exiting gas stream was below the detection limit of the gas analyser, even when the absorbent had the highest CO2 loading of 0.5. Also the SO2 absorption flux remains unchanged with increasing CO2 loading of the solvent. This demonstrates experimentally the basis of the invention. That is, even when exposed to a high concentration of CO2 in the gas stream (relative to SO2) and the solvent is saturated with CO2 (a CO2 loading of 0.5 for MEA), the solvent remains selective for SO2 and absorbs it at the same flux as when the solvent is CO2 free.
As a result of the SO2 degrading the performance of CO2 capture, a restriction of existing PCC technology is that the SO2 content of flue gas must be reduced to less than 10 ppmv before its application. Levels below 10 ppm are normally not achieved in existing flue gas desulfurisation plants and the use of an additional wash step is needed, adding significantly to the investment costs.
For countries such as Australia, where no FGD is applied, the SO2 content of flue gas poses a serious barrier to the use of PCC technology. In such locations FGD must first be installed before CO2 capture can be undertaken, significantly increasing the cost and technical complexity of the process. The most widely practiced FGD technology is based on the use of calcium carbonate slurries to eventually provide a saleable gypsum (calcium sulfate) product. This technology is used in power stations and has a wide range of technology suppliers (eg. Alstom, Babcock-Wilcox, Chiyoda). In some applications a regenerative solvent technology is used, providing a pure SO2 product. CANSOLV Technologies Inc has developed an amine based technology for combined removal of CO2 and SO2 (WO2006/136016). The process uses two different amine based solvents in separate liquid loops which are heat integrated in the separate solvent regeneration steps. The absorption of SO2 and CO2 is performed in the same absorber.
There exists a need for a simple and low cost CO2 capture technology or process that can tolerate the typical levels of SO2 present in untreated flue gas from sulfur containing combustion sources but also from flue gases exiting a typical flue gas desulfurisation process.
It is an object of the present invention to overcome or at least alleviate one or more of the problems associated with the prior art.
Reference to any prior art in the specification is not, and should not be taken as, an acknowledgment or any form of suggestion that this prior art forms part of the common general knowledge in Australia or any other jurisdiction or that this prior art could reasonably be expected to be ascertained, understood and regarded as relevant by a person skilled in the art.